# Talos Energy Inc.: Form 10-Q for the period ended Sep 30, 2023

- Company: [Talos Energy Inc.](/companies/talo.md) (CIK 1724965)
- Form: 10-Q
- Filed: 2023-11-07
- Accepted by EDGAR: Nov 6, 2023, 17:45 ET
- Period: 2023-09-30
- Accession: 0000950170-23-059561
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1724965/000095017023059561/talo-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1724965/000095017023059561/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $383.1m | us-gaap:Revenues |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $1.07bn | us-gaap:Revenues |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $126.8m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $175.0m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-07-01 to 2023-09-30 | $45.6m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2023-01-01 to 2023-09-30 | $128.8m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | −$15.9m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | −$55.5m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | −$2.1m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $101.4m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | −$0.02 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $0.85 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | −$0.02 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $0.86 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 124,103,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 119,262,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $342.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 9 months, 2023-01-01 to 2023-09-30 | $47.5m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2023-09-30 | $13.6m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $411.6m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $4.75bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $629.8m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $2.69bn | us-gaap:Liabilities |
| Long-term debt | at 2023-09-30 | $1.02bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2023-09-30 | $33.1m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2023-09-30 | $2.06bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 69,707 characters.

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2022 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual Report.

### Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico, both upstream through oil and gas exploration and production (“Upstream”) and the development of low carbon solutions opportunities. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

We have historically focused our Upstream operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

We have two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is our only reportable segment. See additional information in Part I, Item 1. “Financial Statements — Note 12 — *Segment Information.”*

### Significant Developments

The following significant development has occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2023.

***Mexico Divestiture —*** On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the Company, to Zamajal, S.A. de C.V, a wholly owned subsidiary of Grupo Carso. See Part I, Item 1. “Financial Statements — Note 2 —*Acquisitions and Divestitures”* for more information.

### Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

***EnVen Acquisition —*** On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information.

***Planned Downtime —*** We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (the “HP-I”) that is operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

During the third quarter of 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a total shut-in period of 41 days. The shut-in resulted in an estimated deferred production of approximately 6.2 MBoepd and 2.1 MBoepd for the three and nine months ended September 30, 2022, respectively, based on production rates prior to the shut-in. The next dry-dock is scheduled for first half of 2024 with a projected shut-in period of approximately 55 days.

During the third quarter of 2022, we experienced approximately 17 days of planned third-party downtime due to maintenance of the Shell Odyssey Pipeline, which carries our production primarily from our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility. Production resumed in October 2022. We estimate the shut-in resulted in the deferred production of approximately 1.8 MBoepd and 0.6 MBoepd for the three and nine months ended September 30, 2022, respectively, based on production rates prior to the shut-in.

***Eugene Island Pipeline System —*** During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field. For the nine months ended September 30, 2022, we estimate the shut-in resulted in deferred production of approximately 1.5 MBoepd based on production rates prior to the shut-in.

### Known Trends and Uncertainties

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2022 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2022 Annual Report.

***Volatility in Oil, Natural Gas and NGL Prices —*** Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.

During the period January 1, 2023 through September 30, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments”* for additional information regarding our commodity derivative positions as of September 30, 2023.

The U.S. Energy Information Administration (“EIA”) published its October 2023 Short-Term Energy Outlook on October 11, 2023. The EIA expects natural gas prices to average more than $3.03 per MMBtu in the fourth quarter of 2023 and $3.23 per MMBtu in 2024. The EIA also expects the NYMEX WTI spot price will average $86.65 per Bbl in the fourth quarter of 2023 and $90.91 per Bbl in 2024. The EIA believes crude oil prices will rise in the coming months, reflecting its expectations of tightening balances in global oil markets. The Israel-Hamas war, which commenced in early October, and the threat of increased conflict in the Middle East raises the potential for oil supply disruptions and higher oil prices. Current OPEC Plus production targets are set to expire at the end of 2024. The EIA assumes that continuing voluntary cuts and other factors will keep actual OPEC Plus crude oil production well below targets as the group tries to limit increases in global oil inventories. However, should OPEC Plus produce closer to target levels than the EIA currently assumes, it could reduce forecasted prices in 2024. Also, the rate at which U.S. tight oil producers add drilling rigs and improve well-level efficiency is highly uncertain and could cause global oil production to vary significantly from the EIA forecast. Finally, the global economic outlook remains uncertain, and unexpected changes in gross domestic product, or GDP, growth in the coming months could affect oil demand.

***Inflation of Cost of Goods, Services and Personnel —*** Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the U.S. Federal Reserve (the “Fed”) and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. The Fed raised rates by a quarter of a percentage point on March 22, 2023; May 3, 2023; and July 26, 2023. The latest interest rate hike increased the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future interest rate hikes remain uncertain.

***Impairment of Oil and Natural Gas Properties —*** Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and nine months ended September 30, 2023 and 2022, we did not recognize an impairment based on the ceiling test computations. At September 30, 2023 our ceiling test computation was based on SEC pricing of $80.46 per Bbl of oil, $3.58 per Mcf of natural gas and $20.44 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2022 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in SEC pricing or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

***BOEM Bonding Requirements —*** In 2016, the BOEM issued the 2016 Notice to Lessees and Operators (“NTL”), which bolstered supplemental bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL, and, in October 2020, pursued a proposed rule published jointly with the BSEE that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and rights of use and easement (“RUE”) and rights of way (“ROW”) grant holders conducting operations on the federal outer continental shelf (“OCS”). The Department of the Interior (the “DOI”) under the Biden Administration elected to separate the BOEM and BSEE portions of the supplemental bonding requirements.

In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations”, wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator for decommissioning within ninety days, and submitting a decommissioning plan within one hundred fifty days.

On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, the BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. The BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. The BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking.

As discussed in our 2022 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM if it submits future demands to cover our decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases,” our ability to obtain adequate supplemental financial assurance (pursuant to a final BOEM rule that is substantially consistent with the June 2023 proposed rule or otherwise), including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our liquidity, financial condition, cash flows, business, properties and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements. Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.

***Deepwater Operations —*** We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

***Oil Spill Response Plan —*** We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE biennially, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

***Hurricanes, Tropical Storms and Loop Currents —*** Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future production and revenues and increased lease operating expenses for evacuations and repairs.

***Five-Year Offshore Oil and Gas Leasing Program Update —*** Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, the BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. President Biden signed the Inflation Reduction Act of 2022 (the “IRA 2022”) into law on August 16, 2022. The IRA 2022 reinstated Lease Sale 257 held in November 2021, and required the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the high bidder on 10 blocks and awarded leases on 9 blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. Lease Sale 261 was scheduled to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States District Court for the Western District of Louisiana, as amended by a September 25, 2023 order from the United States Court of Appeals for the Fifth Circuit. However, on October 26, 2023, the United States Court of Appeals for the Fifth Circuit stayed its and the District Court’s ruling, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced that it is postponing Lease Sale 261 as a result of the Appeals Court’s October 26, 2023 order. BOEM stated it will hold Lease Sale 261 after it receives further direction from the Appeals Court.

BOEM’s development of a new five-year national program typically takes place over several years, during which successive drafts of the program are published for review and comment. At the end of the process, the Secretary of the Interior must submit the Proposed Final Program (“PFP”) to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.

BOEM took the first formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Proposed Program. The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a PFP, which is submitted to Congress and the President for 60 days before implementation. These later program stages also are accompanied by publication of a draft and final Programmatic Environmental Impact Statement (“PEIS”), with a period for public comment on the draft PEIS. The PP and a draft PEIS for the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The PP included no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the PFP for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. Release of the PFP and corresponding Final PEIS initiated the 60-day waiting period required before formal approval occurs and a Record of Decision is finalized.

### How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

- production volumes;
- realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
- lease operating expenses;
- capital expenditures; and
- Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

### Results of Operations

### Revenue

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data):

| Revenues: | Three Months Ended September 30, 2023 | 2022 | Change | Nine Months Ended September 30, 2023 | 2022 | Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $359,404 | $295,585 | $63,819 | $995,081 | $1,078,800 | $(83,719) |
| Natural gas | 16,871 | 68,360 | (51,489) | 53,383 | 181,747 | (128,364) |
| NGL | 6,860 | 13,183 | (6,323) | 24,463 | 49,232 | (24,769) |
| Total revenues | $383,135 | $377,128 | $6,007 | $1,072,927 | $1,309,779 | $(236,852) |
| **Production Volumes:** |  |  |  |  |  |  |
| Oil (MBbls) | 4,451 | 3,258 | 1,193 | 13,358 | 11,020 | 2,338 |
| Natural gas (MMcf) | 6,005 | 7,292 | (1,287) | 19,769 | 24,746 | (4,977) |
| NGL (MBbls) | 403 | 403 | — | 1,318 | 1,372 | (54) |
| Total production volume (MBoe) | 5,855 | 4,876 | 979 | 17,971 | 16,516 | 1,455 |
| **Daily Production Volumes by Product:** |  |  |  |  |  |  |
| Oil (MBblpd) | 48.4 | 35.4 | 13.0 | 48.9 | 40.4 | 8.5 |
| Natural gas (MMcfpd) | 65.3 | 79.3 | (14.0) | 72.4 | 90.6 | (18.2) |
| NGL (MBblpd) | 4.4 | 4.4 | 0.0 | 4.8 | 5.0 | (0.2) |
| Total production volume (MBoepd) | 63.7 | 53.0 | 10.7 | 65.8 | 60.5 | 5.3 |
| **Average Sale Price Per Unit:** |  |  |  |  |  |  |
| Oil (per Bbl) | $80.75 | $90.73 | $(9.98) | $74.49 | $97.89 | $(23.40) |
| Natural gas (per Mcf) | $2.81 | $9.37 | $(6.56) | $2.70 | $7.34 | $(4.64) |
| NGL (per Bbl) | $17.02 | $32.71 | $(15.69) | $18.56 | $35.88 | $(17.32) |
| Price per Boe | $65.44 | $77.34 | $(11.90) | $59.70 | $79.30 | $(19.60) |
| Price per Boe (including realized commodity derivatives) | $64.36 | $60.70 | $3.66 | $59.12 | $56.99 | $2.13 |

The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment due to changes in sales prices and production volumes (in thousands):

| Revenues: | Three Months Ended September 30, 2023 vs 2022 Price | Volume | Total | Nine Months Ended September 30, 2023 vs 2022 Price | Volume | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Oil | $(44,422) | $108,241 | $63,819 | $(312,586) | $228,867 | $(83,719) |
| Natural gas | (39,430) | (12,059) | (51,489) | (91,833) | (36,531) | (128,364) |
| NGL | (6,323) | — | (6,323) | (22,831) | (1,938) | (24,769) |
| Total revenues | $(90,175) | $96,182 | $6,007 | $(427,250) | $190,398 | $(236,852) |

***Three Months Ended September 30, 2023 and 2022 Volumetric Analysis —*** Production volumes increased by 10.7 MBoepd to 63.7 MBoepd. The increase was primarily due to 19.1 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased due to the third party downtime associated with the HP-I dry-dock in our Phoenix Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 6.2 MBoepd and 1.8 MBoepd of deferred production, respectively, during 2022. These increases were partially offset by a decrease of 12.1 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. Additionally, there was approximately 2.4 MBoepd of deferred production resulting from loop currents requiring intermittent shut-ins of the HP-I and associated infrastructure in the Phoenix Field.

***Nine Months Ended September 30, 2023 and 2022 Volumetric Analysis —*** Production volumes increased by 5.3 MBoepd to 65.8 MBoepd. The increase was primarily due to 17.0 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 4.2 MBoepd of deferred production during 2022. These increases were partially offset by a decrease of 14.7 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field.

### Operating Expenses

### Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

|  | Three Months Ended September 30, 2023 | 2022 | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Lease operating expenses | $103,548 | $81,760 | $286,075 | $229,156 |
| Lease operating expenses per Boe | $17.69 | $16.77 | $15.92 | $13.87 |

***Three Months Ended September 30, 2023 and 2022 —*** Lease operating expense for the three months ended September 30, 2023 increased by approximately $21.8 million, or 27%. This increase was primarily related to lease operating expenses of $27.3 million incurred in connection with assets acquired from the EnVen Acquisition. This increase was partially offset by a $3.4 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Pompano Field compared to the same period in 2022.

***Nine Months Ended September 30, 2023 and 2022 —*** Lease operating expense for the nine months ended September 30, 2023 increased by approximately $56.9 million, or 25%. This increase was primarily related to lease operating expenses of $59.0 million incurred in connection with assets acquired from the EnVen Acquisition. Additionally, there was a $11.3 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations. This increase was partially offset by a $22.5 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field compared to the same period in 2022.

### Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

|  | Three Months Ended September 30, 2023 | 2022 | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Depreciation, depletion and amortization | $163,359 | $92,323 | $480,476 | $295,174 |

***Three Months Ended September 30, 2023 and 2022 —*** Depreciation, depletion and amortization expense for the three months ended September 30, 2023 increased by approximately $71.0 million, or 77%. This was due to an increase of $8.88 per Boe, or 47%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in the 2022 Annual Report.

***Nine Months Ended September 30, 2023 and 2022 —*** Depreciation, depletion and amortization expense for the nine months ended September 30, 2023 increased by approximately $185.3 million, or 63%. This was due to an increase of $8.81 per Boe, or 50%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the EnVen Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* and the extension of the HP-I lease during the fourth quarter of 2022, a discussion of which is included in the accompanying Notes to Consolidated Financial Statements in our 2022 Annual Report.

### General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

|  | Three Months Ended September 30, 2023 | 2022 | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Upstream Segment | $21,054 | $23,606 | $108,310 | $59,561 |
| CCS Segment | 2,472 | (22) | 8,246 | 6,358 |
| Unallocated corporate | 1,362 | 1,705 | 4,701 | 4,823 |
| Total general and administrative expense | $24,888 | $25,289 | $121,257 | $70,742 |
| Upstream general and administrative expense per Boe | $3.60 | $4.84 | $6.03 | $3.61 |

***Three Months Ended September 30, 2023 and 2022 —*** General and administrative expense for the three months ended September 30, 2023 decreased by approximately $0.4 million, or 2%. There was a decrease in non-cash equity-based compensation of $3.9 million, primarily due to a forfeiture during the third quarter of 2023. Additionally, Upstream Segment transaction costs related to the closing and continued integration of the EnVen Acquisition decreased $2.8 million or $0.63 per Boe compared to the same period in 2022. This was partially offset by an increase in the CCS Segment’s general and administrative expenses due to the reimbursement of project costs incurred from inception to date from certain partners during the third quarter of 2022. Additionally, payroll expense increased from additional employee headcount primarily related to the EnVen Acquisition.

***Nine Months Ended September 30, 2023 and 2022 —*** General and administrative expense for the nine months ended September 30, 2023 increased by approximately $50.5 million, or 71%. This increase was primarily related to higher Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $34.5 million or $1.89 per Boe. Additionally, there was an increase in payroll expense due to additional employee headcount primarily related to the EnVen Acquisition and the CCS Segment’s general and administrative expenses due to the reimbursement of project costs incurred from inception to date from certain partners during the third quarter of 2022. These increases were partially offset by a decrease in non-cash equity-based compensation of $2.6 million, primarily due to a forfeiture during the third quarter of 2023.

### Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

|  | Three Months Ended September 30, 2023 | 2022 | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Accretion expense | $21,256 | $13,179 | $63,430 | $42,400 |
| Other operating (income) expense | $(57,287) | $(366) | $(55,172) | $12,142 |
| Interest expense | $45,637 | $29,265 | $128,850 | $91,531 |
| Price risk management activities (income) expense | $98,802 | $(114,180) | $13,668 | $231,133 |
| Equity method investment (income) expense | $2,493 | $(991) | $(2,938) | $(14,599) |
| Other (income) expense | $(2,193) | $(692) | $(10,450) | $(31,991) |
| Income tax (benefit) expense | $(15,865) | $121 | $(55,516) | $2,256 |

### Three Months Ended September 30, 2023 and 2022 —

***Accretion Expense —*** During the three months ended September 30, 2023, we recorded $21.3 million of accretion expense compared to $13.2 million during the three months ended September 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

***Other Operating (Income) Expense —*** During the three months ended September 30, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See further discussion in See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”* This gain was partially offset by $8.0 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

***Interest Expense —*** During the three months ended September 30, 2023, we recorded $45.6 million of interest expense compared to $29.3 million during the three months ended September 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes (as defined below under “ — Liquidity and Capital Resources — Overview of Debt Instruments”) assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates and average borrowings when compared to the same period 2022.

***Price Risk Management Activities —*** The expense of $98.8 million for the three months ended September 30, 2023 consists of $92.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $6.3 million in cash settlement losses. The income of $114.2 million for the three months ended September 30, 2022 consists of $195.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $81.2 million in cash settlement losses.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2025, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments.”*

***Income Tax (Benefit) Expense —*** During the three months ended September 30, 2023, we recorded $15.9 million of income tax benefit compared to $0.1 million of income tax expense during the three months ended September 30, 2022. The income tax expense is primarily due to a change of its valuation allowance on its deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — *Income Taxes.”*

### Nine Months Ended September 30, 2023 and 2022 —

***Accretion Expense —*** During the nine months ended September 30, 2023, we recorded $63.4 million of accretion expense compared to $42.4 million during the nine months ended September 30, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”*

***Other Operating (Income) Expense —*** During the nine months ended September 30, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”* This gain was partially offset by $9.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the nine months ended September 30, 2022, we recorded $10.6 million of estimated decommissioning obligations. See Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

***Interest Expense —*** During the nine months ended September 30, 2023, we recorded $128.9 million of interest expense compared to $91.5 million during the nine months ended September 30, 2022. The change is primarily the result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates when compared to the same period 2022.

***Price Risk Management Activities —*** The expense of $13.7 million for the nine months ended September 30, 2023 consists of $10.5 million in cash settlement losses and $3.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of $231.1 million for the nine months ended September 30, 2022 consists of $368.5 million in cash settlement losses offset by $137.4 million in non-cash gains from the increase in the fair value of our open derivative contracts.

***Equity Method Investment (Income) Expense —*** During the nine months ended September 30, 2023, we recorded an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron offset by equity losses of $5.6 million. During the nine months ended September 30, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron offset by equity losses of $0.7 million. See Part I, Item 1. “Financial Statements — Note 10 — *Related Party Transactions”* for additional information.

***Other (Income) Expense —*** During the nine months ended September 30, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

***Income Tax (Benefit) Expense —*** During the nine months ended September 30, 2023, we recorded $55.5 million of income tax benefit compared to $2.3 million of income tax expense during the nine months ended September 30, 2022. The income tax benefit is primarily due to a non-cash tax benefit of $54.9 million related to the partial release of the valuation allowance on our federal deferred tax assets offset by the impact of other permanent differences. The partial release of the valuation allowance is a result of the deferred tax liabilities acquired with the EnVen Acquisition. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 8 — *Income Taxes.”*

### Supplemental Non-GAAP Measure

### EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

- ***EBITDA —*** Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.
- ***Adjusted EBITDA —*** EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

|  | Three Months Ended September 30, 2023 | 2022 | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Net income (loss) | $(2,103) | $250,465 | $101,434 | $379,165 |
| Interest expense | 45,637 | 29,265 | 128,850 | 91,531 |
| Income tax (benefit) expense | (15,865) | 121 | (55,516) | 2,256 |
| Depreciation, depletion and amortization | 163,359 | 92,323 | 480,476 | 295,174 |
| Accretion expense | 21,256 | 13,179 | 63,430 | 42,400 |
| EBITDA | 212,284 | 385,353 | 718,674 | 810,526 |
| Transaction and other (income) expenses(1) | (64,321) | 3,219 | (38,799) | (38,856) |
| Decommissioning obligations(2) | 7,972 | 20 | 9,454 | 10,553 |
| Derivative fair value (gain) loss(3) | 98,802 | (114,180) | 13,668 | 231,133 |
| Net cash received (paid) on settled derivative instruments(3) | (6,313) | (81,162) | (10,474) | (368,483) |
| Non-cash equity-based compensation (income) expense | 393 | 4,310 | 9,080 | 11,677 |
| Adjusted EBITDA | $248,817 | $197,560 | $701,603 | $656,550 |

(1) For the three and nine months ended September 30, 2023, transaction expenses includes $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. For the three and nine months ended September 30, 2022, transaction expenses includes $4.3 million and $5.0 million, respectively, in costs related to the EnVen Acquisition. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* and “Note 7 — *Employee Benefits Plans and Share-Based Compensation.”* Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures.”* The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million for the nine months ended September 30, 2023 and a $1.4 million for the three and nine months ended September 30, 2022. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the nine months ended September 30, 2022. See further discussion in Part I, Item 1. “Financial Statements — Note 10 — *Related Party Transactions.”* For the nine months ended September 30, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

(2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

(3) The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

### Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has decreased since December 31, 2022 primarily due to an increase in our accounts receivables that was offset by an increase in the current portion of long-term debt of $33.1 million related to the 11.75% Notes assumed as part of the EnVen Acquisition. See Part I, Item 1. “Financial Statements — Note 6 — *Debt.”* As of September 30, 2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $752.9 million.

We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities. We are continuing to explore a capital raise to finance the accelerated growth of our CCS Segment.

***Capital Expenditures —*** The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2023 (in thousands):

|  |  |
| --- | ---: |
| U.S. drilling & completions | $317,900 |
| Mexico appraisal & exploration | 291 |
| Asset management(1) | 81,677 |
| Seismic and G&G, land, capitalized G&A and other | 48,493 |
| Total Upstream capital expenditures | 448,361 |
| Plugging & abandonment | 71,097 |
| Decommissioning obligations settled(2) | 40,415 |
| Total Upstream | 559,873 |
| Investment in CCS | 37,183 |
| Total | $597,056 |

(1) Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure.

(2) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 11 — *Commitments and Contingencies.”*

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2023 Upstream capital spending program of $650.0 million to $675.0 million and plugging & abandonment and decommissioning obligations of $120.0 million to $130.0 million as well as expected investments in our CCS Segment of $70.0 million to $90.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

***Common Stock Repurchase Program —*** Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively. As of September 30, 2023, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the imposition of a new 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise task in 2023 based on the fair market value of the stock issuance in connection to the EnVen Acquisition.

***Overview of Cash Flow Activities —*** The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

|  | Nine Months Ended September 30, 2023 | 2022 |
| --- | ---: | ---: |
| Operating activities | $342,811 | $538,928 |
| Investing activities | $(391,874) | $(198,652) |
| Financing activities | $120,309 | $(345,638) |

***Operating Activities —*** Net cash provided by operating activities decreased $196.1 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022 primarily attributable to a decrease from revenues combined with an increase in lease operating expense of $293.8 million.

***Investing Activities —*** Net cash used in investing activities increased $193.2 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022 primarily due to an increase in capital expenditures of $228.9 million and contributions to equity method investees of $27.1 million. Capital expenditures for drilling and completion projects during 2022 generally were budgeted and occurred during the third and fourth quarters. Budgeted capital expenditures for drilling and completion projects for 2023 were more heavily weighted to occur in the first half of 2023. The capital expenditure budget for 2023 also included projects related to the EnVen Acquisition. This was offset by cash proceeds of $74.9 million from the Mexico Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for additional information.

***Financing Activities —*** Cash flow from financing activities changed $465.9 million in the nine months ended September 30, 2023 compared to the corresponding period in 2022. We had net borrowings from the Bank Credit Facility of $215.0 million for the nine months ended September 30, 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures. We had net repayments of $315.0 million during the same period in 2022 due to a management goal to reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for additional information. We repurchased $47.5 million of our common stock through our share repurchase program during the nine months ended September 30, 2023. See the subsection entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Additionally, there was an increase in deferred financing costs of $11.6 million and redemption of senior notes of $8.9 million in each case when compared to the same period in 2022. See Part I, Item 1. “Financial Statements — Note 6 — *Debt”* for additional information.

### Overview of Debt Instruments

***Bank Credit Facility — matures March 2027 —*** We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. See Part I, Item 1. “Financial Statements — Note 6 — *Debt”* for more information.

***12.00% Second-Priority Senior Secured Notes — due January 2026 —*** The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc. (the “Issuer”); the Subsidiary Guarantors (defined below); and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and have interest payable semi-annually each January 15 and July 15. See Part I, Item 1. “Financial Statements — Note 6 — *Debt”* for more information.

***11.75% Senior Secured Second Lien Notes — due April 2026 —*** On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, we assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount outstanding of $257.5 million. The 11.75% Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. We made a payment of $29.2 million on October 16, 2023 for the redemption of outstanding principal and interest incurred. See Part I, Item 1. “Financial Statements — Note 6 — *Debt”* for more information.

***Guarantor Financial Information —*** We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s senior reserve-based revolving credit facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsidiaries (other than Talos International Holdings SCS) and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes.

In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and statement of operations information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the Issuer and the Guarantors for the respective periods (in thousands):

|  | September 30, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Current assets | $400,028 | $344,525 |
| Non-current assets | 4,294,989 | 2,571,254 |
| Total assets | $4,695,017 | $2,915,779 |
| Current liabilities | $628,020 | $599,669 |
| Non-current liabilities | 2,061,239 | 1,285,992 |
| Talos Energy Inc. stockholdersʼ equity | 2,005,758 | 1,030,118 |
| Total liabilities and stockholdersʼ equity | $4,695,017 | $2,915,779 |

The following table presents the statement of operations information for the Issuer and the Guarantors (in thousands):

|  | Nine Months Ended September 30, 2023 |
| --- | ---: |
| Revenues | $1,072,927 |
| Costs and expenses | (968,643) |
| Net income (loss) | $104,284 |

### Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements.

The following table and discussion summarize our material cash requirements from known contractual obligations as of September 30, 2023 (in thousands):

| Long-term financing obligations: | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total(5) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Debt principal | $15,000 | $30,000 | $30,000 | $806,041 | $215,000 | $— | $1,096,041 |
| Debt interest | 11,501 | 120,798 | 117,479 | 65,578 | 5,529 | — | 320,885 |
| Vessel commitments(1) | 9,537 | 1,304 | — | — | — | — | 10,841 |
| Derivative liabilities | 18,141 | 45,882 | — | — | — | — | 64,023 |
| Operating lease obligations | 1,438 | 4,748 | 4,716 | 4,803 | 4,708 | 9,194 | 29,607 |
| Finance lease(2) | 11,602 | 19,336 | — | — | — | — | 30,938 |
| Purchase obligations(3) | 53,058 | 4,579 | — | — | — | — | 57,637 |
| Other commitments(4) | 327 | 2,468 | 2,468 | 2,141 | — | — | 7,404 |
| Total contractual obligations(5) | $120,604 | $229,115 | $154,663 | $878,563 | $225,237 | $9,194 | $1,617,376 |

(1) Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.

(2) Lease agreement for the HP-I floating production facility in the Phoenix Field.

(3) Includes committed purchase orders to execute planned future drilling activities.

(4) Includes commitment to lease acreage and renewals associated with our CCS Segment.

(5) This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $816.8 million as of September 30, 2023. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 3 — *Property, Plant and Equipment.”* Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 11 — *Commitment and Contingencies.”*

***Performance Obligations —*** As of September 30, 2023, we had secured performance bonds totaling $1.4 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 6 — *Debt”* for further information on the Bank Credit Facility.

### Critical Accounting Estimates

Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Except as discussed below, there have been no changes to our critical accounting estimates from those disclosed in our 2022 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

### Determination of Fair Value in Business Combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

The estimated fair value assigned to the assets acquired and liabilities assumed can have a significant effect on our future operating results. For example, a higher fair value measurement of oil and gas properties results in higher depletion expense in future periods which reduces our future earnings.

See Part I, Item 1. “Financial Statements — Note 2 — *Acquisitions and Divestitures”* for more information related to the EnVen Acquisition.

### Recently Adopted Accounting Standards

None.

### Recently Issued Accounting Standards

There were no recently issued accounting standards material to us.

## Market risk

As filed, 1,511 characters.

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2022 Annual Report. Except as discussed below, there have been no material changes from the disclosures presented in our 2022 Annual Report regarding our exposures to certain market risks.

### Price Risk Management Activities

We had commodity derivative instruments in place to reduce the price risk associated with future production of 11,954 MBbls of crude oil and 17,360 MMBtu of natural gas at September 30, 2023, with a net derivative liability position of $48.0 million. For additional information regarding our commodity derivative instruments, see Part I, Item 1. “Financial Statements — Note 5 — *Financial Instruments,”* included elsewhere in this Quarterly Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at September 30, 2023 (in thousands):

|  | Fair Value | Oil and Natural Gas Derivatives Ten Percent Increase Fair Value | Change | Ten Percent Decrease Fair Value | Change |
| --- | ---: | ---: | ---: | ---: | ---: |
| Price impact(1) | $(47,976) | $(133,202) | $(85,226) | $34,441 | $82,417 |

(1) Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

## Controls and procedures

As filed, 1,550 characters.

### Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2023.

### Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 810 characters.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2022 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2022 Annual Report or our other SEC filings including our Quarterly Report on Form 10-Q for the quarter ended March 31, 2023.

Filed Nov 7, 2023.
Source: SEC EDGAR, the filing index for accession 0000950170-23-059561. Last ingested by Listed: Nov 3, 2026, 21:34 ET. No prices; not investment advice.